Lessons Learned from Engineering Analysis of Fracture Injection Tests from Different CBM Reservoirs

Abstract

Abstract With the growing energy demand, operators are looking at exploiting every source of energy and have intensified exploration in coalbed methane (CBM) reservoirs. In the area under consideration, hundreds of wells have been drilled to a few thousands of feet depth covering multiple coal seams. Most of these coal seam reservoirs are CBM reservoirs that need massive dewatering to economically produce the methane gas adsorbed on the coal surface. Hydraulic fracturing has become an important tool that not only enables accelerated dewatering to reduce reservoir pressure to the critical desorption pressure, but also creates a conductive path for gas production and minimizes non-Darcy effects. However, the art of hydraulic fracturing in these unconventional reservoirs is not easy to master. Complex formation behaviors such as poroelasticity, nonideal pressure leakoff, state of formation damage, orientation of cleat system, high fracture gradients, etc. constantly challenge the fracturing design and execution in these unconventional reservoirs. Neglecting pressure responses and having a poor understanding of formation characteristics can compromise the placement of optimized hydraulic fractures, and, ultimately, production results. Hydraulic fracture engineering analysis was performed on all the CBM wells in two exploratory fields and one development field of a CBM basin have been consolidated; the analysis included approximately 40 fracture treatments from these three different fields. Fracture pressure diagnostics such as G-function plots, leakoff mechanisms, and closure pressure analysis, were part of the design, execution, and evaluation cycle to establish and characterize the hydraulic fractures (HF) in the different coal seams. Post-fracture studies completed the design execution and evaluation cycle.